Known solvent-addition and mixing technologies for combining bitumen froth and solvent, such as paraffinic solvent, in a froth treatment process, are limited and have a number of drawbacks and inefficiencies. In some prior methods, there is even a lack of fundamental understanding of the processes and phenomena involved in froth treatment which prevents developing and optimizing existing designs and operations.
In paraffinic froth treatment, for example, a paraffinic solvent is added to a bitumen froth stream and the resulting mixture is sent to a settler vessel to separate it into high diluted bitumen and solvent diluted tailings. The solvent diluted tailings of a first settler vessel may receive an addition amount of paraffinic solvent prior to being supplied into a second settler vessel. There may be several settler vessels arranged in series or in parallel. Addition of the paraffinic solvent allows separation of free water and coarse minerals from the bitumen froth and the precipitation of asphaltenes remove entrained water and fine solids out of the bitumen. The processed high diluted bitumen froth stream is then sent to a solvent recovery unit and then onward for further processing and upgrading to produce synthetic crude oil and other valuable commodities.
Conventional practices for the addition of solvent-containing streams in a froth treatment process use mixers of various configurations, which may have T-junctions, static mixers or in-line mixers. Such conventional practices focus on combining and mixing of the light and heavy hydrocarbon streams with little regard to location of injection, mixing and pipelines relative to settling vessels. In addition, some known methods attempt to control the quantity of shear imparted to the solvent diluted bitumen froth, to balance adequate mixing and avoiding over-shearing. However, the piping and mixing device arrangements in between the solvent addition and the settler vessel have been configured, located and operated without regard to certain flow characteristics, negatively affecting settling performance.
As more general background on PFT in the context of oil sands processing, extraction processes are used to liberate and separate bitumen from oil sand so the bitumen can be further processed. Numerous oil sand extraction processes have been developed and commercialized using water as a processing medium. One such water extraction process is the Clarke hot water extraction process, which recovers the bitumen product in the form of a bitumen froth stream. The bitumen froth stream produced by the Clarke hot water process contains water in the range of 20 to 45%, more typically 30% by weight and minerals from 5 to 25%, more typically 10% by weight which must be reduced to levels acceptable for downstream processes. At Clarke hot water process temperatures ranging from 40 to 80° C., bitumen in bitumen froth is both viscous and has a density similar to water. To permit separation by gravitational separation processes, commercial froth treatment processes involve the addition of a diluent to facilitate the separation of the diluted hydrocarbon phase from the water and minerals. Initial commercial froth treatment processes utilized a hydrocarbon diluent in the boiling range of 76-230° C. commonly referred to as a naphtha diluent in a two stage centrifuging separation process. Limited unit capacity, capital and operational costs associated with centrifuges promoted applying alternate separation equipment for processing diluted bitumen froth. In these processes, the diluent naphtha was blended with the bitumen froth at a weight ratio of diluent to bitumen (D/B) in the range of 0.3 to 1.0 and produced a diluted bitumen product with typically less than 4 weight percent water and 1 weight percent mineral which was suitable for dedicated bitumen upgrading processes. Generally, operating temperatures for these processes were specified such that diluted froth separation vessels were low pressure vessels with pressure ratings less than 105 kPag. Other froth separation processes using naphtha diluent involve operating temperatures that require froth separation vessels rated for pressures up to 5000 kPag. Using conventional vessel sizing methods, the cost of pressure vessels and associated systems designed for and operated at this high pressure limits the commercial viability of these processes.
Heavy oils such as bitumen are sometimes described in terms of relative solubility as comprising a pentane soluble fraction which, except for higher molecular weight and boiling point, resembles a distillate oil; a less soluble resin fraction; and a paraffinic insoluble asphaltene fraction characterized as high molecular weight organic compounds with sulphur, nitrogen, oxygen and metals that are often poisonous to catalysts used in heavy oil upgrading processes. Paraffinic hydrocarbons can precipitate asphaltenes from heavy oils to produce deasphalted heavy oil with contaminate levels acceptable for subsequent downstream upgrading processes. Contaminants tend to follow the asphaltenes when the asphaltenes are precipitated by paraffinic solvents having compositions from C3 to C10 when the heavy oil is diluted with 1 to 10 times the volume of solvent.
High water and mineral content distinguish bitumen froth from the heavy oil deasphalted in the above processes. Some early attempts to adapt deasphalting operations to processing bitumen from oil sands effected precipitation of essentially a mineral free, deasphalted product by addition of water and chemical agents.
Recent investigations and developed techniques in treating bitumen froth with paraffinic use froth settling vessels (FSV) arranged in a counter-current flow configuration. In process configurations, counter-current flow refers to a processing scheme where a process medium is added to a stage in the process to extract a component in the feed to that stage, and the medium with the extracted component is blended into the feed of the preceding stage. Counter-current flow configurations are widely applied in process operations to achieve both product quality specifications and optimal recovery of a component with the number of stages dependent on the interaction between the desired component in the feed stream and the selected medium, and the efficiency of stage separations. In deasphalting operations processing heavy oil with low mineral solids, separation using counter-current flow can be achieved within a single separation vessel. However, rapidly setting mineral particles in bitumen froth preclude using a single separation vessel as this material tends to foul internals of conventional deasphalting vessels.
A two stage paraffinic froth treatment process is disclosed in Canadian Patent No. 2,454,942 (Hyndman et al.) and represented in FIG. 1 as a froth separation plant. In a froth separation plant, bitumen froth at 80-95° C. is mixed with overflow product from the second stage settler such that the solvent to bitumen ratio in the diluted froth stream is above the threshold to precipitate asphaltenes from the bitumen froth. For paraffinic froth treatment processes with pentane as the paraffinic solvent, the threshold solvent to bitumen ratio as known in the art is about 1.2 which significantly increases the feed volume to the settler. The first stage settler separates the diluted froth into a high dilute bitumen stream comprising a partially to fully deasphalted diluted bitumen with a low water and mineral content, and an underflow stream containing the rejected asphaltenes, water, and minerals together with residual maltenes from the bitumen feed and solvent due to the stage efficiency. The first stage underflow stream is mixed with hot recycled solvent to form a diluted feed for the second stage settler. The second stage settler recovers residual maltenes and solvent to the overflow stream returned to the first stage vessel and froth separation tailings. It is important to recognize the different process functions of stages in a counter-current process configuration. In this case, the operation of first stage settler focuses on product quality and the second stage settler focuses on recovery of residual hydrocarbon from the underflow of the first stage settler.
The above known froth treatment processes involve blending diluent into bitumen froth or underflow streams or both.
Initial commercial froth treatment processes added naphtha diluent to reduce viscosity of bitumen for centrifuging. The addition of naphtha diluent also reduced the density of the hydrocarbon phase which together with the reduced viscosity permits gravitational separation of water and minerals from the hydrocarbon phase. Blending of the two streams used a single pipe tee to bring the two fluid streams together with the length of pipe upstream of the separation equipment sufficiently long to permit the streams to blend together without additional inline mixing devices. Improvements to blending of diluent and froth stream such staging the diluent addition were identified as opportunities for future commercial developments.
The initial commercial paraffinic froth treatment process as disclosed by W. Power “Froth Treatment: Past, Present &Future” Oil Sand Symposium, University of Alberta, May 2004 identified counter current of addition of paraffinic diluent as using tee and static mixing to each settler stage. Paraffin addition is also disclosed in CA 2,588,043 (Power et al.).
CA 2,669,059 (Sharma et al.) further discloses a method to design the solvent/froth feed pipe using a tee mixer and the average shear rates and residence times in the feed pipe.
In May 2004, N. Rahimi presented “Shear-Induced Growth of Asphaltene Aggregates” Oil Sand Symposium, University of Alberta, which identified shear history as important for structure and settling behaviour of asphaltene flocs with break up of aggregates by shear as rapid and not fully reversible. In addition, cyclic shear was shown to breakup asphaltene floc aggregates. The hydraulic analysis identified an improved understanding for feeding settler vessels was required for consistent separation performance both in terms of bitumen recovery and the quality of the high diluted bitumen product.
The known practices and techniques experience various drawbacks and inefficiencies, and there is indeed a need for a technology that overcomes at least some of those drawbacks and inefficiencies.